WO2012092203A1 - Validation de systèmes de surveillance de réseau électrique - Google Patents

Validation de systèmes de surveillance de réseau électrique Download PDF

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Publication number
WO2012092203A1
WO2012092203A1 PCT/US2011/067205 US2011067205W WO2012092203A1 WO 2012092203 A1 WO2012092203 A1 WO 2012092203A1 US 2011067205 W US2011067205 W US 2011067205W WO 2012092203 A1 WO2012092203 A1 WO 2012092203A1
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WIPO (PCT)
Prior art keywords
measurement data
measurement
measurement equipment
validation module
ied
Prior art date
Application number
PCT/US2011/067205
Other languages
English (en)
Inventor
Matthew B. Watkins
Normann Fischer
David M. PRESTWICH
Original Assignee
Schweitzer Engineering Laboratories, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Schweitzer Engineering Laboratories, Inc. filed Critical Schweitzer Engineering Laboratories, Inc.
Priority to CA2821771A priority Critical patent/CA2821771A1/fr
Priority to ES201390066A priority patent/ES2457390R1/es
Priority to AU2011352299A priority patent/AU2011352299A1/en
Priority to MX2013005969A priority patent/MX2013005969A/es
Publication of WO2012092203A1 publication Critical patent/WO2012092203A1/fr

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Classifications

    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01R—MEASURING ELECTRIC VARIABLES; MEASURING MAGNETIC VARIABLES
    • G01R19/00—Arrangements for measuring currents or voltages or for indicating presence or sign thereof
    • G01R19/25—Arrangements for measuring currents or voltages or for indicating presence or sign thereof using digital measurement techniques
    • G01R19/2513—Arrangements for monitoring electric power systems, e.g. power lines or loads; Logging
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01R—MEASURING ELECTRIC VARIABLES; MEASURING MAGNETIC VARIABLES
    • G01R35/00—Testing or calibrating of apparatus covered by the other groups of this subclass
    • H02J13/0062—
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E60/00—Enabling technologies; Technologies with a potential or indirect contribution to GHG emissions mitigation
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y04—INFORMATION OR COMMUNICATION TECHNOLOGIES HAVING AN IMPACT ON OTHER TECHNOLOGY AREAS
    • Y04S—SYSTEMS INTEGRATING TECHNOLOGIES RELATED TO POWER NETWORK OPERATION, COMMUNICATION OR INFORMATION TECHNOLOGIES FOR IMPROVING THE ELECTRICAL POWER GENERATION, TRANSMISSION, DISTRIBUTION, MANAGEMENT OR USAGE, i.e. SMART GRIDS
    • Y04S10/00—Systems supporting electrical power generation, transmission or distribution
    • Y04S10/18—Systems supporting electrical power generation, transmission or distribution using switches, relays or circuit breakers, e.g. intelligent electronic devices [IED]

Definitions

  • This disclosure relates to validation and measurement systems and methods in electric power delivery systems. More particularly, this disclosure relates to systems and methods for validating measurements made by unsynchronized devices or time- synchronized devices.
  • FIG. 1 illustrates a one-line diagram of an electric power delivery system, including various voltage potential transformers (PTs) and current transformers (CTs), a monitoring system, and a validation device.
  • PTs voltage potential transformers
  • CTs current transformers
  • FIG. 2A illustrates a one-line diagram of an electric power delivery system, in which a monitoring system includes two independent intelligent electronic devices
  • lEDs the lEDs in communication with a validation device.
  • FIG. 2B illustrates another one-line diagram of an electric power delivery system, in which a data transfer device is used to collect data from each I ED and supply it to the validation device.
  • FIG. 3 illustrates another one-line diagram of an electric power delivery system, including two lEDs configured to monitor various CTs and PTs, one of the lEDs including an integrated validation module.
  • FIG. 4A illustrates a flow diagram of a method for validating monitoring systems, such as lEDs, voltage transformers, and current transformers, using time- synchronized lEDs.
  • FIG. 4B illustrates a flow diagram of a method for validating monitoring systems by aligning the event reports generated by unsynchronized lEDs.
  • FIG. 5 illustrates an example of a flow diagram of a method for selecting a reference time when a reference quantity is above a predetermined threshold.
  • FIG. 6 illustrates an oscillography event report generated by a first IED, including voltage and current measurements for three phases of power in an electric power delivery system.
  • FIG. 7 illustrates an oscillography event report generated by a second I ED, including voltage and current measurements for three phases of power in an electric power delivery system.
  • Intelligent electronic devices may be used for monitoring, protecting and/or controlling industrial and utility equipment, such as in electric power delivery systems.
  • lEDs may be configured to obtain measurement information from current transformers (CTs) and/or voltage potential transformers (PTs).
  • CTs current transformers
  • PTs voltage potential transformers
  • lEDs may be configured to obtain measurement information from a variety of other sources, such as optical current transducers, Rogowski coils, light sensors, relays, temperature sensors, and similar, as well as from measurements, signals, or data provided by other lEDs.
  • lEDs within a power system may be configured to perform metering, control, and protection functions that require a certain level of accuracy.
  • the accuracy of measurement equipment such as CTs and PTs and possibly even lEDs associated therewith may be monitored and/or validated on a regular basis to ensure that they are functioning correctly.
  • regulations and protocols may require that the accuracy of critical measurement equipment be validated on a regular basis.
  • a monitoring system may obtain signals from the electric power system using a first measurement equipment and a second measurement equipment.
  • the monitoring system may be in communication with the first measurement equipment and the second measurement equipment.
  • the monitoring system may include the first measurement equipment and the second measurement equipment.
  • the monitoring system may collect a first set of
  • the monitoring system may comprise a first I ED and a second IED, each IED configured to monitor specific equipment or a specific segment of an electric power delivery system by receiving signals therefrom using a CT.
  • the first IED may collect measurement data obtained by a first CT from one phase of power.
  • the second IED may collect measurement data obtained by a second CT from the same phase of power on the same equipment or segment of the electric power delivery system.
  • the collected measurement data from the first IED may be aligned with the collected measurement data from the second IED.
  • the first and second lEDs may utilize a common time source, such as a time signal provided by a global positioning system (GPS) or via a time-syncing standard such as IEEE 1588. Accordingly, the first and second lEDs may be inherently time-aligned and synchrophasors may be calculated. Additionally, the first and second lEDs may utilize identical or similar sampling and processing algorithms in order to further facilitate the calculations of accurate synchrophasors.
  • GPS global positioning system
  • IEEE 1588 time-syncing standard
  • the first and second lEDs may be inherently time-aligned and synchrophasors may be calculated.
  • the first and second lEDs may utilize identical or similar sampling and processing algorithms in order to further facilitate the calculations of accurate synchrophasors.
  • the first and second lEDs may utilize unsynchronized time signals and/or alternative sampling and processing algorithms.
  • two lEDs may be different models or and/or utilize independent time signals.
  • the data collected may not be inherently time-aligned or easily time-aligned using time stamps associated with the data.
  • an event trigger common to both lEDs may be used to align the measurement data from each IED.
  • each IED may be configured to begin collecting data when a power system event or anomaly is detected, such as when an overcurrent is detected.
  • the two lEDs may independently detect the overcurrent and generate a common event trigger.
  • the common event trigger may be used to align the measurement data collected by each IED.
  • a validation device may calculate phasor amplitudes and/or angles for each IED at a time corresponding to the common event trigger.
  • the calculated phasor amplitudes and/or angles for the measurement data collected by each IED should be approximately the same, since they are aligned with respect to one another using the common event trigger.
  • the validation module may compare the calculated phasor magnitudes and/or angles from the first IED with the calculated phasor magnitudes and/or angles from the second I ED.
  • the validation module may validate the first and/or second measurement equipment, so long as the phasor magnitudes and/or angles from the first and second lEDs are equal or within an acceptable range of one another. If the calculated phasor magnitudes and/or angles are not within an acceptable range of one another, the validation module may transmit a signal indicating that the monitoring system (lEDs and/or one or both of the pieces of measurement equipment) is malfunctioning.
  • the first I ED and the second I ED may function as primary and backup lEDs, respectively. In other embodiments, the first I ED and the second IED may function as dual-primary lEDs. Additionally, any number of lEDs may be used in conjunction with the validation systems and methods described herein. For example, three or four lEDs may be utilized to validate one another in a primary-backup combination or as a plurality of primary lEDs. Throughout the specification, CTs and PTs are used as examples of measurement equipment.
  • CTs computed tomography
  • PTs temperature sensors
  • light sensors Rogowski coils
  • optical current transducers generators
  • transformers transmission lines
  • buses circuit breakers
  • capacitor banks switches
  • voltage regulators voltage regulators
  • tap changers any of a wide variety of measurement equipment, including, but not limited to, CTs, PTs, temperature sensors, light sensors, Rogowski coils, optical current transducers, generators, transformers, transmission lines, buses, circuit breakers, capacitor banks, switches, voltage regulators, and tap changers.
  • the systems and methods described herein may be expanded for use in an enterprise environment in which a validation module or validation device may be in communication with any number (i.e. hundreds or even thousands) of pairs of lEDs functioning in dual-primary or primary-backup
  • a centralized validation system may be capable of remotely validating the functionality of measurement equipment and/or lEDs throughout an electric power delivery system.
  • a validation module or validation device may be adapted to monitor and regularly validate the functionality of measurement equipment and/or lEDs within a substation of an electric power delivery system.
  • the phrases "connected to” and “in communication with” refer to any form of interaction between two or more components, including mechanical, electrical, magnetic, and electromagnetic interaction. Two components may be connected to each other, even though they are not in direct contact with each other, and even though there may be intermediary devices between the two components.
  • I ED may refer to any microprocessor-based device that monitors, controls, automates, and/or protects monitored equipment within a system.
  • Such devices may include, for example, remote terminal units, differential relays, distance relays, directional relays, feeder relays, overcurrent relays, voltage regulator controls, voltage relays, breaker failure relays, generator relays, motor relays, automation controllers, bay controllers, meters, recloser controls, communications processors, computing platforms, programmable logic controllers (PLCs),
  • PLCs programmable logic controllers
  • lEDs may be connected to a network, and communication on the network may be facilitated by networking devices including, but not limited to, multiplexers, routers, hubs, gateways, firewalls, and switches. Furthermore, networking and communication devices may be incorporated in an IED or be in communication with an IED.
  • the term I ED may be used interchangeably to describe an individual IED or a system comprising multiple lEDs.
  • a computer may include a processor, such as a microprocessor,
  • the processor may include a special purpose processing device, such as an ASIC, PAL, PLA, PLD, Field Programmable Gate Array, or other customized or programmable device.
  • the computer may also include a computer-readable storage device, such as non-volatile memory, static RAM, dynamic RAM, ROM, CD-ROM, disk, tape, magnetic, optical, flash memory, or other computer- readable storage medium.
  • Suitable networks for configuration and/or use, as described herein, include any of a wide variety of network infrastructures. Specifically, a network may incorporate landlines, wireless communication, optical connections, various modulators,
  • demodulators small form-factor pluggable (SFP) transceivers, routers, hubs, switches, and/or other networking equipment.
  • SFP small form-factor pluggable
  • the network may include communications or networking software, such as software available from Novell, Microsoft, Artisoft, and other vendors, and may operate using TCP/IP, SPX, IPX, SONET, and other protocols over twisted pair, coaxial, or optical fiber cables, telephone lines, satellites, microwave relays, modulated AC power lines, physical media transfer, wireless radio links, and/or other data transmission "wires".
  • the network may encompass smaller networks and/or be connectable to other networks through a gateway or similar mechanism.
  • a software module or component may include any type of computer instruction or computer executable code located within or on a computer-readable storage medium.
  • a software module may, for instance, comprise one or more physical or logical blocks of computer instructions, which may be organized as a routine, program, object, component, data structure, etc., that performs one or more tasks or implements particular abstract data types.
  • a particular software module may comprise disparate instructions stored in different locations of a computer-readable storage medium, which together implement the described functionality of the module.
  • a module may comprise a single instruction or many instructions, and may be distributed over several different code segments, among different programs, and across several computer-readable storage media.
  • software modules may be located in local and/or remote computer- readable storage media.
  • data being tied or rendered together in a database record may be resident in the same computer-readable storage medium, or across several computer-readable storage media, and may be linked together in fields of a record in a database across a network.
  • FIG. 1 illustrates simplified one-line diagram of an electric power delivery system 100 that is monitored, protected, controlled, and/or metered by a monitoring system 105.
  • monitoring system 105 may comprise one or more intelligent electronic devices (lEDs).
  • Electric power delivery system 100 may include a bus 108, and a conductor 1 06.
  • Electric power delivery system 100 may comprise a transmission system, in which case conductor 106 may be a transmission line.
  • Electric power delivery system 100 may comprise a distribution system, in which case conductor 106 may be a feeder.
  • monitoring system 105 may be configured to monitor measurement and monitoring devices associated with transformers, generators, distribution lines, transmission lines, buses, circuit breakers, capacitor banks, switches, voltage regulators, tap changers, and/or other monitoring and measurement equipment associated with electric power delivery systems.
  • Monitoring system 105 may be in communication with measurement equipment, such as current transformers (CTs) 1 14 and 1 16 and voltage potential transformers (PTs) 1 10 and 1 12.
  • CTs 1 14 and 1 16 and PTs 1 10 and 1 12 may be configured to generate signals corresponding to electrical conditions of a portion of the electric power delivery system 100.
  • PTs 1 10 and 1 12 may be configured to each generate a signal corresponding to the voltage on bus 108.
  • CTs 1 14 and 1 16 may be configured to each generate a signal corresponding to the current passing through conductor 106.
  • the pair of PTs 1 10 and 1 12 may be configured to function in a dual-primary configuration, or in a primary-backup configuration.
  • CTs 1 14 and 1 16 may also be configured as dual-primary or primary-backup measurement equipment.
  • Monitoring system 105 may receive signals from the electric power delivery system using measurement equipment 1 10, 1 12, 1 14, and 1 16 and generate an event report comprising measurement data. For example, monitoring system 105 may receive the signals from measurement equipment 1 10, 1 12, 1 14, and 1 16 and generate an event report of measurement data along a time line for each individual piece of measurement equipment 1 10, 1 12, 1 14, and 1 16. According to various embodiments, monitoring system 105 may begin collecting measurement data from measurement equipment 1 10, 1 12, 1 14, and 1 16 upon receiving a trigger from an external source. Alternatively, monitoring system 105 may collect measurement data in response to an event trigger.
  • an event trigger may be automatically generated by the monitoring system 105 in response to the detection of an overcurrent, undercurrent, overvoltage, voltage drop, overfrequency, underfrequency, change in frequency, and/or other power system anomaly.
  • Monitoring system 105 may also be configured to actuate breaker 120 and remove conductor 106 from service in response to the detection of an overcurrent, undercurrent, overvoltage, voltage drop, overfrequency, underfrequency, change in frequency, and/or other power system anomaly.
  • Monitoring system 105 may also be in communication with a validation device 150.
  • Validation device 150 may be configured to receive event reports associated with each piece of measurement equipment 1 10, 1 12, 1 14, and 1 16. Validation device 150 may record and/or evaluate each of the event reports.
  • validation device 150 may include a Supervisory Control and Data Acquisition (SCADA) system, a Real-Time Automation Controller (RTAC) or other automation controller, a synchrophasor vector processor (SVP), and/or other such device capable of receiving and processing information from lEDs.
  • SCADA Supervisory Control and Data Acquisition
  • RTAC Real-Time Automation Controller
  • SVP synchrophasor vector processor
  • Validation device 150 may be in direct communication with monitoring system 105, or may communicate with monitoring system 105 using a network or physical transport of media.
  • Validation device 150 may be in the same building/substation as monitoring system 105, or a remote building or remote location.
  • Validation device 150 may include a validation module 152 configured to evaluate information received from monitoring system 105.
  • validation module 152 may include computer code configured to process and analyze
  • the validation module may be configured to receive the event reports associated with each pair of measurement equipment 1 10, 1 12, 1 14, and 1 16 monitoring the same portion of the electric power delivery system 100.
  • CTs 1 14 and 1 16 may be considered a pair of measurement equipment each monitoring the same electrical condition of conductor 106.
  • pair of PTs 1 10 and 1 12 may each monitor the same electrical condition of bus 108.
  • validation module 152 may receive an event report associated with each piece of measurement equipment 1 10, 1 12, 1 14, and 1 16 in a pair of measurement equipment 1 10, 1 12 and 1 14, 1 16. Validation module 152 may then compare the two event reports with respect to one another in order to validate each of the measurement equipment with respect to one another.
  • the event reports and measurement data collected by monitoring system 105 may be time- synchronized, such as in embodiments in which the lEDs within monitoring system 105 are time-synchronized.
  • synchrophasors may be calculated using the event reports associated with each of CT 1 14 and 1 16.
  • monitoring system 105 may collect unsynchronized measurement data and generate unsynchronized event reports, such as in situations in which monitoring system 105 comprises multiple unsynchronized lEDs.
  • validation module 152 may be adapted to align the event reports.
  • the event reports may be aligned using various methods of data alignment.
  • the event reports may be
  • the event reports associated with pairs of measurement equipment may be aligned using common event triggers.
  • a first I ED may generate an event trigger in response to the detection of an overcurrent event via CT 1 14.
  • a second I ED may generate an event trigger in response to the same overcurrent event detected via CT 1 16.
  • the event trigger may be common to both the first I ED and the second I ED. While the time stamps for each of the first and second lEDs may be different, validation module 152 may use the common event triggers to align the event reports associated with each of CT 1 14 and CT 1 16. Similarly, lEDs receiving signals from PT 1 10 and PT 1 12 may generate common event triggers that can be used by validation module 152 to align their associated event reports.
  • FIG. 2A illustrates an example of a one-line diagram of a power delivery system 200, in which a monitoring system (105 of FIG. 1 ) comprises an IED 202 and an IED 204.
  • IED 202 may be in communication with PT 210 configured to generate a signal corresponding to a voltage potential of bus 208 and CT 216 configured to generate a signal corresponding to a current through conductor 206.
  • IED 204 may be in communication with PT 212 configured to generate a signal
  • IEDs 202 and 204 may be in a dual-primary configuration or in a primary-backup configuration.
  • IED 202 may be considered a primary IED for monitoring conductor 206 and bus 208 via CT 216 and PT 210, respectively.
  • IED 204 may be either a second primary IED or a backup I ED for monitoring conductor 206 and bus 208 via CT 214 and PT 212, respectively.
  • I ED 202 may receive signals from each of PT 210 and CT 216 and generate an event report including measurement data.
  • I ED 204 may receive signals from each of PT 212 and CT 214 and generate an event report including measurement data.
  • each of lEDs 202 and 204 may generate an event report of measurement data along a time line for each respective piece of measurement equipment 210, 212, 214, and 216.
  • lEDs 202 and 204 may begin collecting measurement data from the measurement equipment 210, 212, 214, and 216 upon receiving a trigger from an external source.
  • lEDs 202 and 204 may collect measurement data in response to an event trigger.
  • an event trigger may be automatically generated by each of l EDs 202 and 204 in response to the detection of an overcurrent, undercurrent, overvoltage, voltage drop, overfrequency, underfrequency, change in frequency, and/or other power system anomaly.
  • One or both of lEDs 202 and 204 may also be configured to actuate breaker 220 in order to remove conductor 206 from service in response to the detection of an overcurrent, undercurrent, overvoltage, voltage drop, overfrequency, underfrequency, change in frequency, and/or other power system anomaly.
  • Validation device 250 may be configured to receive event reports associated with each piece of measurement equipment 210, 212, 214, and 216. As illustrated, each of lEDs 202 and 204 may be capable of independently communicating with validation device 250. Alternatively, validation device 250 may communicate with each of lEDs 202 and 204 via a communications network or though the physical transport of media.
  • validation device 250 may include a validation module 252 configured to evaluate event reports associated with measurement equipment 210, 212, 214, and 216.
  • the validation module 252 may be configured to receive the event reports from each pair of measurement equipment, i.e. PTs 210 and 212 monitoring bus 208 and CTs 214 and 216 monitoring conductor 206.
  • Validation module 252 may compare the event reports associated with PT 210 to the event reports associated with PT 212.
  • validation module 252 may compare the event reports associated with CT 216 to the event reports associated with CT 214.
  • lEDs 202 and 204 may be different models and/or utilize unsynchronized time signals.
  • the event reports of measurement equipment 210, 212, 214, and 216 in a pair of measurement equipment 210, 212 and 214, 216 may not be time-synchronized.
  • validation module 252 may be adapted to align the event reports.
  • the event reports may be aligned using various methods of data alignment.
  • the event reports may be graphically represented and aligned using automated graphical or image alignment techniques.
  • the event reports associated with each pair of measurement equipment 210, 212 and 214, 216 may be aligned using common event triggers.
  • I ED 204 may generate an event trigger in response to an overcurrent event on conductor 206 detected via CT 214.
  • IED 202 may generate an event trigger in response to the same overcurrent event on conductor 206 detected via CT 216.
  • the event trigger may be common to both IED 202 and IED 204. While the time stamps for each of lEDs 202 and 204 may be different, validation module 252 may use the common event triggers to align the event reports associated with each of CT 214 and CT 216. Similarly, the event reports associated with each of PT 210 and PT 212 may be aligned using common event triggers.
  • FIG. 2B illustrates an alternative embodiment of a one-line power delivery system 290, in which a data transfer device 225 is used to collect the event reports from each IED 202 and 204.
  • the data transfer device may be an SEL-4391 Data Courier®, available from Schweitzer Engineering Laboratories, Inc. in Pullman,
  • the data transfer device may be any device capable of performing the functions of collecting and distributing data from the lEDs, such as a laptop computer, a tablet computer, a smart phone, or the like.
  • each IED 202 and 204 may include a data port 203 and 205, respectively, adapted to transfer event reports associated with various measurement equipment, such as CTs 214 and 216 and PTs 210 and 212, to data transfer device 225 via data port 251 .
  • Data transfer device 225 may then be used to transfer the event reports to validation device 250.
  • validation device 250 may include a validation module 252 configured to evaluate event reports associated with each piece of measurement equipment 210, 212, 214, and 216.
  • the validation module may receive the event reports from each pair of measurement equipment, i.e. PTs 210 and 212 monitoring bus 208 and CTs 214 and 216 monitoring conductor 206.
  • Validation module 252 may compare the event reports associated with PT 210 to the event reports associated with PT 212, and validation module 252 may compare the event reports associated with CT 216 to the event reports associated with CT 214.
  • the event reports associated with measurement equipment in a pair of measurement equipment may not be time- synchronized. Accordingly, validation module 252 may be adapted to align the event reports using common event triggers, as described above.
  • FIG. 3 illustrates another alternative embodiment of an electric power delivery system 300, in which a validation module 352 is integrated within an I ED 304.
  • an I ED 304 may monitor, protect, and/or control various aspects of electric power delivery system 300.
  • IED 304 may monitor line 306 via CT 314.
  • IED 304 may also monitor bus 308 via PT 312.
  • IED 304 may actuate breaker 320 in order to remove line 306 from service in response to the detection of an overcurrent, undercurrent, overvoltage, voltage drop, overfrequency, underfrequency, change in frequency, and/or other power system anomaly.
  • IED 304 may receive and collect measurement data from signals generated by each of CT 314 and PT 312.
  • IED 304 may generate an event report, including measurement data, based on the signals provided by each of CT 314 and PT 312.
  • IED 302 may be configured to function with respect to IED 304 in a dual-primary configuration or in a primary-backup configuration. IED 302 may monitor, protect, and/or control various aspects of line 306 and bus 308. For example, IED 302 may monitor line 306 via CT 316. IED 302 may also monitor bus 308 via PT 310. IED 304 may actuate breaker 320 in order to remove line 306 from service in response to the detection of an overcurrent, undercurrent, overvoltage, voltage drop, overfrequency, underfrequency, change in frequency, and/or other power system anomaly. IED 302 may receive and collect measurement data from signals generated by each of CT 316 and PT 310. IED 302 may generate an event report including the measurement data based on the signals provided by each of CT 316 and PT 310.
  • IED 304 may include an integrated validation module 352 configured to receive event reports associated with each of CT 314 and PT 312 generated by IED 304, and event reports associated with each of CT 316 and PT 310 generated by IED 302.
  • Validation module 352 may evaluate the event reports associated with CT 314 and CT 316 in order to validate the functionality of CTs 314 and 316 and/or lEDs 304 and 302.
  • validation module 352 may evaluate the event reports associated with PT 312 and PT 310 in order to validate the functionality of PT 312 and PT 310 and/or lEDs 304 and 302.
  • lEDs 302 and 304 may be different models and/or utilize unsynchronized time signals.
  • Validation module 352 may be adapted to align the event reports using an event trigger common to both I ED 302 and 304.
  • the event reports may be aligned using various methods of data alignment, graphical alignment, and/or image alignment.
  • I ED 304 may generate an event trigger in response to the detection of a voltage drop on bus 308 via PT 312.
  • I ED 302 may generate an event trigger in response to the same voltage drop on bus 308 detected via PT 310.
  • validation module 352 may use the common event triggers to align the event reports associated with each of PT 310 and PT 312.
  • FIG. 4A illustrates a flow diagram of a method 400 for validating monitoring systems that may include, for example, , lEDs, monitoring equipment such as PTs, CTs, temperature sensors, light sensors, Rogowski coils, optical current transducers, generators, transformers, transmission lines, buses, circuit breakers, capacitor banks, switches, voltage regulators, tap changers, and/or other measurement equipment associated with electric power delivery systems.
  • monitoring equipment such as PTs, CTs, temperature sensors, light sensors, Rogowski coils, optical current transducers, generators, transformers, transmission lines, buses, circuit breakers, capacitor banks, switches, voltage regulators, tap changers, and/or other measurement equipment associated with electric power delivery systems.
  • a validation module may retrieve event reports from a first I ED and a second I ED, at 404.
  • the first I ED may provide an event report containing measurement data from a CT or a PT corresponding to an electric condition of a portion of an electric power delivery system.
  • the second I ED may provide an event report containing measurement data from a CT or a PT corresponding to the same electric condition of the same portion of the electric power delivery system.
  • each I ED may provide an event report containing measurement data from a CT corresponding to a current flow in a conductor in the electric power delivery system.
  • the first and second lEDs may be time-synchronized. Accordingly, time stamps associated with each event report may be synchronized.
  • the validation module may then align the event reports from the time-synchronized lEDs, at 406.
  • the validation module may then select a reference time when a reference quantity is above a given threshold, at 408. For example, the validation module may determine a current value above a predetermined threshold at a given time using the event report associated with a CT generated by the first I ED.
  • the validation module may then calculate phasor magnitudes and/or angles for each IED at the first time, at 410.
  • the validation module may compare the phasor magnitudes and/or angles from the first IED to those of the second IED in order to calculate an accuracy indicator using the phasor magnitudes and/or angles, at 412. For example, in order to calculate an accuracy indicator for the magnitudes, the validation module may take the difference between the magnitude associated with the first IED and the magnitude associated with the second IED, multiply the difference by 100, and then divide by the magnitude of the first IED. In order to calculate an accuracy indicator for the angles, the validation module may take the difference between the angle associated with the first IED and the angle associated with the second IED, multiply by 100, and divide by 180.
  • the validation module may report that the CT, or other measurement equipment, are functioning correctly, at 416. If the accuracy indicator is outside of a predetermined range, at 414, then the validation module may take a predetermined action, at 418, such as provide an alert or sound an alarm.
  • a first IED and a second IED may not be time-synchronized.
  • each IED may utilize an independent time source and/or utilize a different sampling algorithm.
  • FIG. 4B illustrates a method 450 for validating monitoring systems using unsynchronized lEDs.
  • a validation module may retrieve event reports from a first IED and a second IED, at 454.
  • the first IED may provide an event report containing measurement data from various CTs and PTs monitoring each phase of a three-phase electric power delivery system.
  • the second IED may provide an event report containing measurement data from various CTs and PTs monitoring each phase of the same three-phase electric power delivery system.
  • each IED may provide an event report containing measurement data from a CT and a PT corresponding to a current flow and a voltage potential in each phase of a three-phase power conductor.
  • the time stamps associated with each event report may also be unsynchronized.
  • the validation module may then align the event reports using an event trigger common to both lEDs, at 456.
  • the first IED may generate an event trigger in response to the detection of an anomaly in the three-phase power system.
  • a second I ED may generate an event trigger in response to the same anomaly in the three-phase power system.
  • the validation module may use the common event triggers to align the event reports associated with each of the CTs and PTs.
  • the validation module may then select a reference time when a reference quantity is above a given threshold, at 458. For example, the validation module may determine a current or voltage value above a predetermined threshold at a given time using the event report associated with a CT or a PT generated by the first I ED. The validation module may calculate phasor magnitudes and angles for the first IED at the reference time, at 460. The validation module may also calculate phasor magnitude and angles for the second IED at the reference time, at 462.
  • Table 1 illustrates example measurements taken from two lEDs configured to monitor a three-phase power system using CTs and PTs.
  • IED 1 may monitor phases A, B, and C using CTs and PTs in order to generate an event report containing measurement data.
  • the validation module may then determine the phasor magnitude and angle for each channel, using the current on phase A, as measured by the first IED, as a reference quantity.
  • the second IED may monitor phases A, B, and C using CTs and PTs in order to generate an event report containing measurement data.
  • the validation module may determine the phasor magnitude and angle for each channel, using the current on phase A as a reference quantity.
  • the validation module may compare the phasor magnitudes and angles from the first IED to those of the second IED in order to calculate an accuracy indicator, at 464.
  • Table 2 below illustrates accuracy indicators calculated for each CT and PT associated with each of phases A, B, and C. Table 2
  • the validation module may take the difference between the magnitude associated with the first IED and the magnitude associated with the second IED, multiply the difference by 100, and then divide by the magnitude of the first IED.
  • the validation module may take the difference between the angle associated with the first IED and the angle associated with the second IED, multiply by 100, and divide by 180. If an accuracy indicator is within a predetermined range, at 466, then the validation module may report that the measurement equipment, and/or the lEDs are functioning correctly, at 468.
  • the validation module may take a predetermined action, at 470, such as provide an alert or sound an alarm.
  • a predetermined action such as provide an alert or sound an alarm.
  • Alternative methods, values, and algorithms may be used to calculate an accuracy indicator. The method used to calculate an accuracy indicator may be adapted and modified as is found useful without departing from the scope of the present disclosure.
  • the example illustrated in Figures 4A and 4B and described above shows calculation of an accuracy indicator for measurements at a single point (aligned voltages and current measurements at a single point).
  • the validation device may calculate accuracy indicators for aligned measurement data at multiple points.
  • the validation device may calculate accuracy indicators for aligned
  • FIG. 5 illustrates an example of a flow diagram of a method 500 for selecting a reference time when a reference quantity is above a predetermined threshold.
  • a validation module may receive event reports from a first IED and a second IED. The validation module may then analyze the voltage and current magnitudes at a first time, at 550. In one embodiment, the validation module may determine a reference time based on an acceptable reference quantity between 0 and 10 cycles before or after an event trigger. In another embodiment, a reference time may be associated with an acceptable reference quantity at any time recorded in an event report.
  • the voltage on phase A is above a voltage threshold, at 552, then the voltage on phase A at the first time may be used as a reference, at 554.
  • the voltage on phase B is above a voltage threshold, at 556, then the voltage on phase B at the first time may be used as a reference, at 558. Otherwise, if the voltage on phase C is above a voltage threshold, at 560, then the voltage on phase C at the first time may be used as a reference, at 562. Otherwise, if the current on phase A is above a current threshold, at 564, then the current on phase A at the first time may be used as a reference, at 566. Otherwise, if the current on phase B is above a current threshold, at 568, then the current on phase B at the first time may be used as a reference, at 570. Otherwise, if the current on phase C is above a current threshold, at 572, then the current on phase C at the first time may be used as a reference, at 574.
  • the time may be incremented, at 576, and the process repeated, beginning at 552, until a reference time can be selected that corresponds to a reference voltage or current that is above a minimum threshold.
  • the voltage and/or current measurements on the three phases may be compared against the threshold values in any order.
  • the voltage or current with the highest magnitude may be chosen if more than one voltage or current measurement is above a threshold voltage or current.
  • FIGs. 6 and 7 illustrate oscillography event reports including voltage and current measurements for three phases of power in an electric power delivery system.
  • FIG. 6 illustrates measurements collected by a first IED from CTs and PTs in
  • FIG. 7 illustrates measurements collected by a second IED from CTs and PTs in communication with the same three phases, phases A, B, and C, of the same segment in the electric power delivery system.
  • the first IED (FIG. 6) and the second IED (FIG. 7) are not time-synchronized.
  • the illustrated oscillography reports are merely examples and may not be to scale or accurate representations of real-world voltage and current measurements.
  • the first IED may have detected an event and inserted an event trigger 604 at about cycle 3.25, after which the current of phase A can be seen to dramatically increase. Additionally, the voltage of phase A can be seen to slightly decrease at after event trigger 604.
  • Analytic assistant window 606 may provide numerical information, such as time stamps, dates, and voltage and current
  • the current on phases A, B, and C may have magnitudes of 3965.2, 354.4, and 380.0, respectively.
  • the voltage on phases A, B, and C may have magnitudes of 59.2, 80.8, and 79.5, respectively.
  • the second IED may have detected an event and inserted an event trigger 704 at about cycle 2, after which the current of phase A can be seen to dramatically increase. Additionally, the voltage of phase A can be seen to slightly decrease after event trigger 704.
  • Analytic assistant window 706 may provide numerical information, such as time stamps, dates, and voltage and current measurements.
  • the current on phases A, B, and C may have magnitudes of 3775.3, 352.8, and 375.0, respectively.
  • the voltage on phases A, B, and C may have magnitudes of 60.0, 80.5, and 79.5, respectively.
  • a validation module may utilize any one of the previously described methods to align the event reports of FIGs. 6 and 7 in order to validate that the various CTs, PTs, and/or the lEDs are functioning correctly.
  • the validation module may align the event reports using the event triggers 604 and 704.
  • the validation module may select a reference time when a reference quantity is above a given threshold. The magnitude of the current on phase A in FIG. 6 at the time of the event trigger may be used as a reference quantity.
  • the validation module may calculate phasor magnitudes and angles for the first IED (FIG. 6) at the reference time (i.e. at the time of the event trigger).
  • the validation module may also calculate phasor magnitude and angles for the second IED (FIG. 7) at the reference time.
  • Table 1 included above, corresponds to the
  • the validation module may calculate an accuracy indicator for each set of data, as illustrated in Table 2 above. If the accuracy indicators are within predetermined acceptable thresholds, then the validation module may validate the monitoring system, including the associated measurement equipment, such as the underlying CTs and/or PTs, and/or associated lEDs. Otherwise, if the accuracy indicators are outside of predetermined thresholds, then the validation module may provide an alert or sound an alarm.

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  • General Physics & Mathematics (AREA)
  • Engineering & Computer Science (AREA)
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  • Remote Monitoring And Control Of Power-Distribution Networks (AREA)

Abstract

La présente invention concerne des systèmes et procédés pour la validation de systèmes de surveillance de réseau électrique, comprenant, entre autres, des transformateurs de courant et des transformateurs de potentiel de tension. Selon divers modes de réalisation, un premier dispositif électronique intelligent contrôle une partie d'un système de distribution d'énergie électrique à travers un ou des transformateur(s) de courant et/ou un ou des transformateur(s) de potentiel de tension. Un second dispositif électronique intelligent contrôle une partie du système de distribution d'énergie électrique à travers un ou des transformateur(s) de courant et/ou un ou des transformateur(s) de potentiel de tension. Chaque dispositif électronique intelligent peut générer un rapport d'événements, contenant des données de mesure, associées à chaque équipement de mesure respectif. Un module de validation peut comparer les rapports d'événements afin de valider que les dispositifs électroniques intelligents et/ou l'équipement de mesure de courant opérant sous eux fonctionnement correctement. Selon divers modes de réalisation, le module de validation peut être configuré pour aligner les rapports d'événements provenant des deux dispositifs électroniques intelligents au moyen d'un déclencheur d'événements commun aux dispositifs électroniques intelligents.
PCT/US2011/067205 2010-12-27 2011-12-23 Validation de systèmes de surveillance de réseau électrique WO2012092203A1 (fr)

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CA2821771A CA2821771A1 (fr) 2010-12-27 2011-12-23 Validation de systemes de surveillance de reseau electrique
ES201390066A ES2457390R1 (es) 2010-12-27 2011-12-23 Validación de sistemas de monitorización de sistemas de energía eléctrica
AU2011352299A AU2011352299A1 (en) 2010-12-27 2011-12-23 Validation of electric power system monitoring systems
MX2013005969A MX2013005969A (es) 2010-12-27 2011-12-23 Validacion de sistemas de monitoreo de sistema de energia electrica.

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US13/335,547 US9435835B2 (en) 2010-12-27 2011-12-22 Validation of electric power system monitoring systems

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MX2013005969A (es) 2013-07-17
AU2011352299A1 (en) 2013-06-06
ES2457390A2 (es) 2014-04-25

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